In long horizontal wells, the production rate at the heel is often higher than that at the toe. The resulting imbalanced production profile may cause early water or gas breakthrough into the wellbore. Once coning occurs, well production may severely decrease due to limited flow contribution from the toe. To eliminate this imbalance, flow control devices (FCDs) are placed in each screen joint to balance the production influx profile across the entire lateral length and to compensate for permeability variations. By restraining, or normalizing, flow through high flow rate sections, FCDs create higher drawdown pressures and thus higher flow rates along the borehole sections that are more resistant to flow. This corrects uneven flow caused by the heel-toe effect and heterogeneous permeability.
Currently, there are four primary types of passive FCD designs in the industry: nozzle-based (restrictive) (FIG. 1), helical channel (frictional) (FIG. 2), tube-type (combination of restrictive and friction) (FIG. 3) and hybrid channel (combination of restrictive, some friction and a tortuous pathway) (FIG. 4). They use four different methods to generate the pressure drop that helps to normalize flow.
The nozzle-based FCD uses fluid constriction to generate an instantaneous differential pressure across the device by forcing the fluid from a larger area down through small diameter port, creating a flow resistance. The benefits of nozzle-based FCD are its simplified design and easier nozzle adjustment immediately before deployment in a well should real-time data indicate the need to change flow resistance. The disadvantage of nozzles is that small diameter ports are required to create flow resistance, which make them prone to erosion from high-velocity fluid-borne particles during production and susceptible to plugging, especially during any period where mud flow back occurs.
The helical channel FCD uses surface friction to generate a differential pressure across the device. The helical channel design is one or more flow channels that wrapped around the base pipe. This design provides for a distributed pressure drop over a relatively long area, versus the instantaneous loss using a nozzle. Because the larger cross-sectional flow area of the helical channel FCD generates significantly lower fluid velocity than the nozzles of a nozzle-based FCD with a same flow resistance rating (“FRR”), the helical channel FCD is more resistance to erosion from fluid-borne particles and resistant to plugging during mud flow back operations. The disadvantage of helical-channel FCD is that its flow resistance is more viscosity-dependent than the nozzle-based FCD, thus start-up in a steam based method, such as SAGD, can be delayed. The cost of delayed production has been estimated at $2M/month (assuming production is completely restricted for a month). The viscosity dependence could also allow preferential water flow should premature water breakthrough occur. Also, the helix FCD is not adjustable.
The tube-type FCD design incorporates a series of tubes. The primary pressure drop mechanism is restrictive, but in long tubes. This method essentially forces the fluid from a larger area down through the long tubes, creating a flow resistance. Because of the additional friction resistance, the larger cross-sectional flow area of the tube-type FCD generates lower fluid velocity than the nozzles of a nozzle-based FCD with a same FRR, the tube-type FCD is more resistance to erosion from fluid-borne particles and resistant to plugging during mud flow back operations. However, since the friction resistance is much less than the local resistance, the tube-type FCD is less viscosity-dependent than a helical channel FCD having the same FRR.
The hybrid FCD design incorporates a series of flow slots in a maze pattern. Its primary pressure drop mechanism is restrictive, but in a distributive configuration. A series of bulkheads are incorporated in the design, each of which has one or more flow cuts at an even angular spacing. Each set of flow slots are staggered with the next set of slots with a phase angle thus the flow must turn after passing through each set of slots. This prevents any jetting effect on the flow path of the downstream set of slots, which may induce turbulence. As the production flow passes each successive chamber that is formed by bulkheads, a pressure drop is incurred. Pressure is reduced sequentially as the flow passes through each section of the FCD. Without the need to generate the pressure drop instantaneously, the flow areas through the slots are relatively large when compared to the nozzle design of same FRR, thus dramatically reducing erosion and plugging potential.
Although FCDs are a well-developed completion technology, they have only recently been applied to enhanced oil recovery methods, such as SAGD. SAGD is the most extensively used concept for in situ development of the million plus centipoises bitumen resources in the McMurray Formation in the Alberta Oil Sands. SAGD uses long horizontal well pairs, with a horizontal producer located near the bottom of the pay and a horizontal steam injector typically spaced about five meters (4-10 m) above, and parallel to, the producer. Steam is continuously injected into both wells during start-up to form a steam chamber along the length of the wells and establish fluid communication between the well pair. Once the steam chamber is well developed and the well pair are in fluid communication, steam is typically only injected into the injection well. Heavy oil heats at the edges of the steam chamber, gravity drains to the lower production well, where it and any condensed water are then produced.
Even development of the steam chamber is needed in SAGD, and the well completion is designed to optimize this. The standard SAGD well design used at Surmont, for example, employs 800 to 1000 meter slotted liners with tubing strings landed near the toe and near the heel in both the injector and the producer to provide two points of flow distribution control in each well. Steam is injected into both tubing strings at rates that are controlled so as to place more or less steam at each end of the completion, thus achieving better overall steam distribution along the horizontal wells.
Likewise, the producer is initially gas-lifted through both tubing strings at rates controlled to provide better inflow distribution along the completion. If steam were injected only at the heel of the injector, and water and bitumen were produced only from the heel of the producer, the tendency would be for the steam chamber to develop only near the heel. This would result in limited rates and poor steam chamber development over much of the horizontal completion. Indeed, even with toe tubing strings, seismic surveys indicate that steam chamber growth is uneven, and typically there is only about 50% conformance.
Stalder was the first to investigate and publish a study of the flow distribution control of FCDs in a SAGD reservoir. See SPE-153706-MS (2012). For that test, toe tubing was used during preheat, but removed for the test. The producer liner consisted of 59 joints of 6⅝ inch base pipe, each having a helical channel FCD and a 17 feet long sand exclusion element. The injector liner consisted of 62 joints of 6⅝ inch base pipe, of which 41 joints had a helical channel FCD with a six inch wire-wrapped screen sand exclusion element, and 21 joints were blank pipe spaced throughout the liner. Each liner joint was 47 feet long in both the producer and the injector.
The typical liner design in this reservoir has slots cut throughout the surface of every joint of liner in both the producer and the injector, except for a short length near each coupling, so that over 90% of the liner length is slotted. In contrast, the FCD test had only a fraction open for fluid flow. In the producer only 36% of the length of the liner was open screen and 64% was blank pipe. The injector liner was only 0.7% open screen, and 99.3% was blank pipe.
Based on the observations of the above helical channel FCD-deployed SAGD well pair, Stalder concluded that an FDC-deployed single tubing completion achieved similar or better steam conformance as compared to the standard toe/heel tubing injection. In addition, the FCD completion significantly reduced tubing size, which in turn reduced the size of slotted liner, intermediate casing, and surface casing. The smaller wellbore size increased directional drilling flexibility and reduced drag making it easier and lower cost to drill the wells. Thus, Stalder concluded wells could be drilled much longer than current SAGD wells, which tend to be between 500 and 1000 m.
Although all FCD's offer benefit, the reality is that none of these FCDs meets the ideal requirements of an FCD designed for the life of a SAGD well—high resistance to plugging and erosion, high viscosity insensitivity, and yet at the same time allows for flow control of the more complex flow profiles from enhanced oil recovery methods, such as SAGD where oil viscosity is higher during startup, where temperatures have not yet reached a high, but viscosity reduces as the temperature increases and where steam flashing is a potential problem. Therefore, the selection and optimization of FCDs for specific reservoirs, especially heavy oil reservoirs, is still needed in the art.
To gain the potential economic benefits from an FCD and to select the most appropriate FCD device for a given situation, a need to better understand FCD behavior in SAGD operations has been expressed by several SAGD operators. However, characterization data from vendors tends to be limited and sporadic. In all cases the rate/pressure relationships for the FCDs were available only for liquid water or oil at low temperature, not for steam and high temperature oil conditions present in a SAGD well. Yet, steam flashing is a critical parameter to consider in any steam based oil recovery method.
Initial characterization of FCDs often relates the pressure drop across the tool as a function of the Reynolds Number (Re). This relationship between ΔP and Re has been the most advanced formulation to represent FCDs in a thermal reservoir simulator. However, this approach is only valid as long as no phase change occurs through the device (water flashing to steam for example).
Thus, what is still needed in the art are better modeling methods to predict the FCD behavior under reservoir conditions, particularly under enhanced oil recovery conditions such as seen with SAGD. In particular, a method to better account for behavior under the unique conditions presented by steam based enhanced recovery methods would be beneficial.